1. Field of the Invention
The present invention relates to a new microemulsion system for rapid cleanup and enhanced production of hydrocarbon-containing fluids in fractured tight subterranean formations and to methods for making and using same.
More particularly, the present invention relates to a new microemulsion system for rapid clean up and enhanced production of hydrocarbon-containing fluids in fractured tight subterranean formations, where the microemulsion system includes a surfactant subsystem including one monoalkyl branched propoxy sulfate or a plurality of monoalkyl branched propoxy sulfates, a solvent subsystem and a co-solvent subsystem and to methods for making and using same.
2. Description of the Related Art
Historically the use of microemulsion systems for water block cleaning purposes and enhanced gas production purposes date back to at least 1992.
For example, U.S. Pat. No. 5,310,002 disclosed formulations based on microemulsions, where the microemulsion includes (i) an alkyl alcohol having in the range of from 4 to 18 carbon atoms microemulsified into the treatment fluid; (ii) a microemulsifying agent present in an amount sufficient to form and maintain a stable microemulsified dispersion of the alkyl alcohol in the treatment fluid; (iii) a microemulsion mutual solvent selected from the group consisting of glycol ethers and alkyoxylates of glycol ethers; and (iv) a microemulsion co-solvent selected from the group consisting of polyethylene glycol, primary alcohols and alkyoxylates of alkyl alcohols.
U.S. Pat. No. 6,911,417 disclosed a formulation, and method for removing water from a near-wellbore portion of a subterranean formation containing a crude oil and penetrated by a wellbore surfactant systems, where the formulation includes alkylpolyglycoside, ethoxylated alcohols and linear alkyl alcohol or the formulation includes a hydrocarbonaceous liquid, alkylpolyglycoside, ethoxylated alcohol and linear alkyl alcohol.
United States Published Pat. Appln. No. 20030166472 disclosed a microemulsion well treatment microemulsion that is formed by combining a solvent-surfactant blend with a carrier fluid. In preferred embodiments, the solvent-surfactant blend includes a surfactant and a solvent selected from the group consisting of terpenes and alkyl or aryl esters of short chain alcohols.
In many instances, when wellbores are drilled to penetrate a subterranean oil-bearing formation, it is found that upon completion of the wellbores, whether using an oil-based drilling mud, water-based drilling mud or water-based drill-in-fluids, the near-wellbore portion of the formation frequently retains quantities of water greater than the in-situ or natural water saturation levels of the formation. The in-situ water saturation levels are typically nearly, if not the same, as the connate water saturation levels although in some formations the in-situ water saturation levels may be substantially greater or less than the connate water saturation level for the formation.
As used herein, the term “connate water saturation” or “irreducible water saturation” refers to the minimum water saturation in a subterranean oil-bearing formation that can be achieved by flushing with oil, thereby increasing the oil saturation and the flowing fraction of the oil phase. This can be ascertained or determined in a formation core that has been cleaned, dried and fully water saturated and thereafter flooded with oil. The water remaining after the oil flush is nearly equal or equal to the connate water saturation level and cannot be reduced further by oil flushing or oil contact. The term “in-situ water saturation” refers to the pre-existing formation water saturation level prior to drilling or oil production.
Formations drilled for the production of crude oil are naturally-occurring formations, which as well known to the art, underlie overburden formations and may be above other oil-bearing or non-oil-bearing formations beneath the formation of interest. When such formations are drilled, it is known that they typically have at least an in-situ saturation, which is most commonly the connate (residual saturation) water content. This water content is the inherent water saturation level in the formation and may be increased by the invasion of water-based drilling fluid filtrate components. Typically, the presence of water in excess of the in-situ water saturation level in the formation inhibits the production of crude oil from the formation.
In some formations, it has been noted that the formation has an in-situ water saturation level lower than the connate water saturation level, i.e., the formation actually imbibes water during drilling so that the formation as drilled may retain water up to or beyond the connate water saturation level. In such formations, the imbibed water up to the connate water saturation level is not typically removed by the production of crude oil. The water is only reduced back to the connate water saturation level for the formation through natural mechanisms. The presence of water above the in-situ water saturation level can and does typically inhibit the production of crude oil from the formation.
Previously, attempts to reduce water in the near-wellbore portion of the formation either back to the connate level or below have involved the use of materials such as a mixture of methanol and water or the like, in attempts to remove the water with aqueous solutions that are at least partially soluble in the crude oil. The use of such approaches, while they may have had limited success in some instances, are generally less than completely successful and are less desirable because of the safety concerns on the use of highly flammable methanol solvent.
Various applications wherein alkylpolyglycosides in combination with ethoxylated alcohols, alcohols and the like have been used in aqueous formations are shown in U.S. Pat. No. 4,985,154 issued Jan. 15, 1991 to Balzer, et al; U.S. Pat. No. 5,725,470 issued Mar. 10, 1998 to Lazarowitz, et al; U.S. Pat. No. 5,830,831 issued Nov. 3, 1998 to Chan, et al; U.S. Pat. No. 5,874,386 issued Feb. 23, 1999 to Chan, et al; U.S. Pat. No. 5,977,032 issued Nov. 2, 1999 to Chan; U.S. Pat. No. 6,000,412 issued Dec. 14, 1999 to Chan, et al; U.S. Pat. No. 6,090,754 issued Jul. 18, 2000 to Chan, et al; and U.S. Pat. No. 6,112,814 issued Sep. 5, 2000 to Chan, et al. These patents are hereby incorporated by reference.
In other instances, it has been found that water occasionally tends to accumulate to levels above the connate water saturation level in the near-wellbore area during production of oil from the well. As the water accumulates, it successively reduces the flowing fraction of the oil phase, and therefore the production of oil from the formation. This water becomes trapped in the pore structure of the formation and remains in place and does not move with the flow of crude oil from the formation.
Although numerous microemulsion systems have been produced for use in the oil and gas industry, there is still a need the art for other microemulsion systems for use in the oil and gas industry or in related industries.